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Collaborating Authors
Results
Enhanced Oil Recovery Experiments in Wolfcamp Outcrop Cores and Synthetic Cores to Assess Contribution of Pore-Scale Processes
Kamruzzaman, Asm (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines) | Kneafsey, Timothy J (Lawrence Berkeley Laboratory) | Reagan, Matthew T (Lawrence Berkeley Laboratory)
Abstract This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recoveryโboth for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution. We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160ยฐF using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a โhuff-and-puffโ process. The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm while it was 6.98 cm in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs. The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture. This research provides a basis for interpreting core flooding oil recovery results under expansion drive and gas injection EORโboth in presence and absence of interconnected micro- and macro-fractures in the flow path. Finally, the CO2 injection results quantify the CCUS efficacy in regard to the amount of sequestered CO2 from pore trapping in the early reservoir life. For the long-term CO2 trapping, one needs to include the chemical interaction of CO2 with the formation brine and rock matrix.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.89)
- Overview (0.67)
- Research Report (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (31 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Laboratory Analyses and Compositional Simulation of the Eagle Ford and Wolfcamp Shales: A Novel Shale Oil EOR Process
Bustin, Amanda Marilyn (The University of British Columbia) | Bustin, R. Marc (The University of British Columbia) | Downey, Robert (Shale Ingenuity LLC) | Venepalli, Kiran (Computer Modeling Group Ltd)
Abstract Cyclic injection-flowback (huff and puff, HnP) of natural gas or carbon dioxide has been shown to improve the recovery of oil from low permeability, low porosity shale reservoirs. However, natural gas and carbon dioxide are limited in effectiveness and utility; natural gas has a high miscibility pressure and high mobility and hence potential for leak-off and inter-well communication; carbon dioxide is not readily available, is costly, and corrosive. In this study, a novel shale oil HnP EOR process, utilising a liquid solvent comprised of mixtures of propane and butane (C3 and C4), referred to as SuperEOR (Downey et al, 2021), was evaluated for its efficacy in recovering oil compared to methane and carbon dioxide. The advantages of the propane and butane solvent are its low miscibility pressure with the produced oil, it is injected as a liquid, and is easy to separate and recycle. In this study, an Eagle Ford shale core with produced Eagle Ford oil and a Permian Wolfcamp shale core with produced Wolfcamp oil were investigated. PVT and minimum miscibility tests of the fluids were combined with petrophysical analysis to design laboratory tests and provide metrics for tuning a compositional model. Two Eagle Ford facies were investigated, a calcite/quartz-rich mudstone/siltstone with a porosity of up to 10% and a calcite-rich limestone with porosity ranging from 3% to 6%. At reservoir stress, the matrix permeability averages about 2E-4 md. One facies of the Wolfcamp shale was tested, which is 80% quartz, has a porosity of about 7-11%, and average matrix permeability of 9E-3 md. SuperEOR was carried out on core plugs re-saturated with produced oil for 16 days at reservoir conditions of 5000 psi at 101ยฐC for the Eagle Ford and 79ยฐC for the Wolfcamp. For the Eagle Ford shale, five to 6 HnP cycles using a 1:1 ratio of C3 and C4, at injection pressures of 5000 and 3000 psi, with 20 hours of soaking per cycle, yielded a recovery of 55% to 75% of the original oil in place (OOIP) for the lower porosity facies and over 80% for the higher porosity facies of the Eagle Ford. For the Wolfcamp shale, at an injection pressure of 3000 psi, 85% of the original oil in place was recovered using 1:1 ratio of C3 and C4. In comparison, the Wolfcamp shale, at similar experiment conditions and number of HnP cycles, yielded about 30% of the OOIP when methane was used as an injectant/solvent and yielded 75% of OOIP when carbon dioxide was used. The efficacy of the HnP process on the Eagle Ford shale at the core scale was investigated through reservoir modelling using a general equation-of-state compositional simulator and the results were compared to the laboratory data and a field scale EOR simulation on three horizontal wells using carbon dioxide, methane, and the C3:C4 solvent. The wells had a production rate of <3 bbl/day prior to shut-in and responded poorly to natural gas HnP EOR due to excessive leak-off. The HnP simulations comprise cycling 23 days of injection followed by 30 days of production for 17 years. The recovery utilising methane is 45%, carbon dioxide 72%, and 90% with the C3:C4 solvent for the field simulation, which are generally similar to the laboratory tests and the core simulation.
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (28 more...)
Phase Behavior and Minimum Miscibility Pressure of Confined Fluids in Organic Nanopores
Song, Yilei (China University of Petroleum, Beijing) | Song, Zhaojie (China University of Petroleum, Beijing) | Liu, Yueliang (China University of Petroleum, East China) | Guo, Jia (China University of Petroleum, Beijing) | Bai, Baojun (Missouri University of Science and Technology) | Hou, Jirui (China University of Petroleum, Beijing) | Bai, Mingxing (Northeast Petroleum University) | Song, Kaoping (China University of Petroleum, Beijing)
Abstract Phase equilibrium of shale fluid is highly disturbed due to liquid adsorption and capillary pressure in densely-developed organic nanopores. And the miscibility phenomenon between gas and oil is also changed during gas injection for enhanced oil recovery (EOR). Therefore, it is imperative to develop a general framework of theoretical models and algorithm to investigate the effect of pore proximity on phase behavior and miscibility of confined fluids in shale formations. In this study, first, an improved vapor/liquid equilibrium (VLE) calculation model is presented to calculate the phase behavior of confined fluids based on our modified Peng-Robinson equation of state (A-PR-EOS) which can reflect the effect of adsorption. The capillary pressure across the interface and the critical property shift of pure component are also taken into account. An improved Young-Laplace equation is utilized to simulate capillarity and the shifted critical properties can be obtained using the A-PR-EOS. Then, a prediction process for the phase behavior of a quaternary mixture (CO2, CH4, n-C4H10, n-C10H22) is performed, and the results are compared against the experimental data from previous literature, yielding an average error of 1.29%. Results indicate that the presence of nanopore confinement could decrease the density difference between the liquid and vapor phase of the quaternary mixture, and thus induce the reduction of interfacial tension (IFT). As pore size becomes smaller, the IFT decreases rapidly, especially when the pore radius (Rp) is less than 20 nm. Furthermore, the vanishing interfacial tension (VIT) algorithm and the modified VLE procedure are applied to determine the minimum miscibility pressure (MMP) of Bakken shale oil with CO2. The MMP is reduced from 20.2 MPa at 50 nm pores to 17.5 MPa at 20 nm pores. Hence, the reduction of pore size leads to a decrease in MMP, i.e. the CO2 and the reservoir fluid could reach miscibility at a lower pressure, which is beneficial for CO2-EOR. The proposed model could provide a consistent description of fluid phase behavior over the whole range of pore sizes in the Bakken, and could be applied to guide the development of shale hydrocarbon reservoirs, such as reserves and production estimates.
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract A CO2 huff-n-puff pilot implemented in the Midland Basin demonstrated a significant oil rate improvement, but also witnessed an escalation in water-cut up to 0.3. A compositional model was established to consider the complex physics including cyclic stress changes, reopening of water-bearing layers, reopening of unpropped fractures and its resulting relative permeability shift. Our previously published work suggested that the reopening of unpropped fractures and its resulting relative permeability shift contributes most to the abnormal water cut surge after gas injection. In this study, we further proposed several operational constraints to manage such high water-cut occurrence after gas injection. The optimized simulation results suggested that around 1.5 times increase in recovery factor can be achieved after six CO2 huff-n-puff cycles. Sensitivity analysis was subsequently conducted regarding parameters such as soaking time, injection time, and bottom-hole pressure. It was found that soaking time and bottom-hole pressure did not have much influence on cumulative oil production. Setting injection time as 150 days in each cycle can achieve the highest net present value. The primary objective of this study is aimed at optimizing techniques for conducting CO2 huff and puff process to maximize oil production and minimize CO2 emission.
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.35)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
Abstract The Hydraulic Fracturing Test Site (HFTS) in the Permian-Midland basin has bridged the gap between inferred and actual properties of in-situ hydraulic fractures by recovering almost 600 feet of the whole core through recently hydraulically fractured upper and middle Wolfcamp formations. In total, over 700 hydraulically induced fractures were encountered in the core and described, thus providing indisputable evidence of fractures and their attributes, including orientation, propagation direction, and composite proppant concentration. This fracture data, along with the collected diagnostics, support testing and calibration of the next generation fracture models for optimizing initial completion designs and well spacing. In addition, with a massive number of existing horizontal wells in the Permian, the collected data is also useful for designing and implementing enhanced oil recovery (EOR) pilots to improve resource recovery from the existing wells. It is known from the literature that the primary recovery from the shale wells is typically about 5-10% of the original oil in place. Therefore, tremendous potential exists in the Permian to recover additional hydrocarbons by implementing appropriate EOR techniques on the existing wells. To explore this concept, Laredo Petroleum and GTI have agreed to perform HFTS Phase-2 EOR field pilot near the original HFTS, supported by funding from the U.S. Department of Energy and industry sponsors. The Phase-2 EOR field pilot involves injecting field gas into a previously fracture stimulated well in order to produce additional oil using huff-and-puff technique. During the course of the EOR experiment, a second slant core well was drilled near the injection/production well to capture and describe some of the fractures which served as a conduit for the injected gas field during the injection or "huff" period and the produced fluids during the production or "puff" period. The overreaching goals of the HFTS Phase-2 EOR experiment is to determine the effectiveness of cycling gas injection in increasing the oil and gas recovery from the Wolfcamp shale. Specific objectives included: 1. Drill, core, and instrument a second slant core well to describe the fracture network in the vicinity of an EOR injector/producer well 2. Perform laboratory experiments to determine the phase behavior, including black oil study, slim tube analysis, swell testing, etc. 3. Demonstrate how natural gas and/or CO2 increases the oil recovery from Wolfcamp shale through core flooding experiments 4. Determine if pre-existing stimulated horizontal wells can be re-pressurized above the miscibility pressure using the field gas 5. Perform numerical 3D reservoir simulations to predict EOR injection/production performance 6. Instrument offset wells and collect diagnostic data during the cyclic gas injection and production test. This paper describes the EOR field pilot along with the collected data and performed analyses noted above.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.77)
- Geology > Geological Subdiscipline (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Information Technology > Modeling & Simulation (0.66)
- Information Technology > Communications > Networks (0.46)
Use of In-Situ CO2 Generation in Liquid-Rich Shale
Ogbonnaya, Onyekachi (University of Oklahoma, Norman, Oklahoma, USA) | Wang, Shuoshi (Southwest Petroleum University, Chengdu, China) | Shiau, Benjamin (University of Oklahoma, Norman, Oklahoma, USA) | Harwell, Jeffrey (University of Oklahoma, Norman, Oklahoma, USA)
Abstract Modified in situ CO2 generation was explored as an improved tool to deliver CO2 indirectly to the target liquid rich shale formations. Once injected, the special CO2- generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO2. For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches. In this effort, in situ CO2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 ยฐF. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism. Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort. Multiple researchers reported successful lab scale CO2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO2 generation potential for liquid rich shale reservoirs.
- North America > United States > Oklahoma (1.00)
- Europe (0.93)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- (5 more...)
Abstract Decline curve analysis has been used as a reliable method to forecast conventional reservoir well production over the last decades. Recently, an increase in the demand for oil and gas has caused unconventional reservoirs to become a prominent source of energy. However, it is challenged if we still apply the decline curve analysis in unconventional reservoirs due to its limitations such as boundary dominated flow, constant operation condition, et al. Therefore, in this paper, two new methods are proposed using machine learning method to forecast well production in unconventional reservoirs, especially on the EOR pilot projects. The first method is the Neural Network, which allows the analysis of large quantities of data to discover meaningful patterns and relationships. Both peak production rate and hydraulic fracture parameters are used to be the key factors. Lastly, Neural Network technology is applied to investigate the relationship between key factors and oil production rate. The second method uses the Time Series Analysis. Time Series Analysis is one of the most applied data science techniques in business and finance. Since the properties of unconventional reservoir make the production prediction more difficult, it is safe to say that Time Series Analysis can yield good results on the production rate forecast. Field production data from over 1000 wells from different shale plays (Barnett, Bakken, Bone Springs, Eagle Ford oil, Eagle Ford gas, Fayetteville, Marcellus gas, Marcellus oil, Utica oil, and Woodford) is used to verify the feasibility of these two methods. The results indicate there is a good match between the available and predicated production data. The overall R values of Neural Network and Time Series Analysis are above 0.8, which demonstrates that Neural Network and Time Series Analysis are reliable to study the dataset and provide proper production prediction. Meanwhile, when dealing with the EOR production prediction, such as Huff-n-Puff, Time Series Analysis shows more accurate results than Neural Network. This paper proposes a thorough analysis of the feasibility of machine learning in multiple unconventional reservoirs. Instead of repeatedly fitting the production data by decline curve analysis, it also provides a more robust way and meaning reference for the evaluation of the wells.
Abstract Pilot tests of surfactant additives in completion fluid and gas huff n' puff in depleted wells have proven the possibility of production enhancement in unconventional liquid reservoirs (ULR). However, numerical simulation studies regarding EOR techniques neglect two important features of the ULR: extensive fracture discontinuity and high fracture density. This work explores how these two features effect depletion forecasts and EOR evaluation in ULR by applying discrete fracture network (DFN) modeling and optimized unstructured gridding. In this study, grid generation algorithms for Perpendicular Bisection (PEBI) gridding are improved to handle reservoirs with complex fracture geometry and high fracture intensity. The depletion behavior of the dual-porosity methods and the DFN method are compared based on the "sugar-cube" conceptual model. Data including outcrop maps and FMI log are used to characterize fracture network geometry and build DFN models to represent realistic stimulated tight reservoirs. Dynamic fluid flow models are calibrated through history matching of depletion. To properly model EOR processes at the field scale, results from publications of lab experiments regarding surfactant imbibition and CO2 huff n' puff are used to generate simulation parameters. A series of surfactant spontaneous imbibition and gas huff n' puff simulations are performed on those calibrated DFN models to study the impact of fracture geometry on EOR performance. Simulation results indicate that dual-porosity methods are not correct if the transient period of fracture-matrix flow lasts for extaned periods or the continuity of fractures is poor, both of which are very common in ULR. By tuning parameters within a reasonable range, DFN dynamic fluid flow models match the production data and can represent the realistic stimulated ULR. Surfactant assisted spontaneous imbibition (SASI) in the matrix domain results in a marginal production increase compared to water imbibition. It is found that wettability alteration incurred in the fracture system may play a more important role in production enhancement. Simulation results of gas huff n' puff indicate the main recovery mechanisms are re-pressurization and viscosity reduction characteristic of multicontact miscibility. And for reservoirs below the bubble-point, another recovery mechanism is the increase of heavy components' flux. However, either increasing the soak period or increasing the portion of the production period in each cycle has a minor effect on recovery enhancement. This study reveals the significance of using DFN with the unstructured grid to study the EOR processes in ULR. This approach can capture the rapid and extreme change in phase saturation and component fraction within the stimulated reservoir volume (SRV). Our results demonstrate the important factors that affect the field-scale EOR performance in ULR.
- North America > United States > Texas (1.00)
- North America > Canada (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geology > Petroleum Play Type > Unconventional Play (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (28 more...)
Abstract CO2 storage through CO2 enhanced oil recovery (EOR) is considered as one of the technologies to help promote larger scale deployment of CO2 storage because of associated economic benefits through oil recovery, 45Q tax credits and the utilization of existing infrastructure. The objective of this study is to demonstrate how optimal reservoir management and operation strategies (including well completions and controls) can be used to optimize both CO2 storage and oil recovery. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection/oil production controls that maximize the net present value (NPV) in a CO2 EOR and storage operation. We utilized the newly developed StoSAG algorithm, one of the most efficient optimization algorithms in the reservoir management community, to solve the optimization problem. The performance of joint optimization approach was compared with the performance of well control only optimization approach. In addition, the performance of co-optimization of CO2 storage and oil recovery approach was compared with the performances of maximization of only CO2 storage and maximization of only oil recovery approaches. The optimization results showed that a joint optimization of well completions and well controls can achieve an 8.84% higher final NPV than the one obtained from the optimization of only well controls. It was observed that the NPV incremental for joint optimization is mainly due to the fact that the optimal well completions and controls approach results in efficient CO2 storage and oil production from different reservoir layers depending on the differences in individual layer properties. Comparison of co-optimization (i.e., maximization of NPV) and maximization of only CO2 storage or only oil recovery showed that the co-optimization and maximization of only oil recovery result in significantly higher final NPV than that obtained through maximization of only CO2 storage approach while maximization of only CO2 storage can achieve significantly higher CO2 storage in the reservoir compared to the other two scenarios. The similar results for co-optimization and maximization of oil production are obtained because of the difference in oil revenue compared to CO2 storage tax credit. To the best of our knowledge, this is the first study in oil/gas industry and CO2 storage community to perform joint optimization of well completions and well controls in the fields. We expect that the proposed optimization framework will be a useful and efficient tool for field engineers to optimally manage CO2 EOR projects to maximize revenue through oil recovery as well as CO2 storage by taking advantage of the new 45Q tax law.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.94)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (26 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)
Abstract The purpose of this paper is to (1) describe the mechanisms of gas-based enhanced oil recovery (EOR) in tight unconventionals, and (2) emphasize the need for single-porosity model tuning of the dual-porosity model when it is used to model EOR for unconventionals on well or field scale. We study two different gas-based EOR methods that inject and produce cyclically through the same well: The Huff-n-Puff (HnP) method, and a method we will refer to as the Fracture-to-Fracture (F2F) in which every other hydraulic fracture is used for injection and production in each cycle. We show that the recovery mechanisms and EOR target volume for HnP and F2F are fundamentally different. We argue that the target volume for HnP is a rubblized ("shattered") rock volume adjacent to the hydraulic fracture. To accurately predict the performance of this rubblized region, we use a compositional reservoir simulator that includes molecular diffusion to model the EOR performance of rubble-rock pieces of varying size. Gridding of numerical models is given considerable attention for both HnP and F2F to show its importance when modeling miscible EOR processes. Coarse gridding may result in significant numerical dispersion, which can falsely yield artificially optimistic recoveries for the HnP process. Results from this paper show that the primary recovery mechanism for HnP stems from a target EOR volume represented by a rubblized rock volume. The size of the rubble, and in particular its minimum dimension, will control the amount of gas that enters, mixes, and recovers oil from the rubble pore space through a process of Darcy flow, molecular diffusion, and phase behavior that involves swelling, vaporization, and first-contact miscibility conditions. The F2F method is not particularly affected by the rubblized region, but instead targets recovery from the entire rock volume between hydraulic fractures; this EOR process is akin to a conventional miscible-displacement mechanism with a much larger EOR target than HnP. The F2F method is presented in this paper as an alternative to the HnP method to show that HnP is not necessarily the best or the only EOR strategy in tight unconventionals. The EOR target volume for F2F is potentially much larger than for HnP, as everything between the fractures may be swept with a piston-like efficiency. However, the response time (i.e. the time before uplift in production is observed) can be much longer for F2F than HnP, depending mainly on the fracture spacing and matrix permeability.
- North America > United States > Texas (1.00)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- (3 more...)